2020 Summer Reliability Assessment - June 2020 - NERC
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2020 Summer Reliability Assessment June 2020
Summer Reliability Assessment 2
Table of Contents
Preface .......................................................................................................................... 3 Regional Assessment Dashboards .................................................................................... 17
About this Report ............................................................................................................ 4 MISO ........................................................................................................................... 18
Findings ......................................................................................................................... 5 MRO-Manitoba Hydro.................................................................................................... 19
Resource Adequacy ......................................................................................................... 6 MRO-SaskPower............................................................................................................ 20
Changes from Year-to-Year............................................................................................... 7 NPCC-Maritimes ............................................................................................................ 21
Internal Demand ............................................................................................................. 8 NPCC-New England ........................................................................................................ 22
Pandemic Preparedness and Operational Assessment—Summer 2020.................................... 9 NPCC-New York ............................................................................................................. 23
Operational Risks Highlighted for Summer 2020 .................................................................14 NPCC-Ontario ............................................................................................................... 24
NPCC-Québec ............................................................................................................... 25
PJM ............................................................................................................................. 26
SERC ............................................................................................................................ 27
SPP.............................................................................................................................. 30
Texas RE-ERCOT ............................................................................................................ 31
WECC .......................................................................................................................... 32
Data Concepts and Assumptions ...................................................................................... 35
Summer Reliability Assessment 3
Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO) Enterprise serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised
of the North American Electric Reliability Corporation (NERC) and the six Regional Entities (REs), is a highly reliable and secure North American bulk power system (BPS). Our mission is to assure the effective
and efficient reduction of risks to the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is divided into six RE boundaries as shown in the map and corresponding table below. The multicolored area denotes overlap as some load-serving entities participate in one
Region while associated Transmission Owners/Operators participate in another.
MRO Midwest Reliability Organization
NPCC Northeast Power Coordinating Council
RF ReliabilityFirst
SERC SERC Reliability Corporation
Texas RE Texas Reliability Entity
WECC Western Electricity Coordinating CouncilSummer Reliability Assessment 4 About this Report NERC’s 2020 Summer Reliability Assessment (SRA) identifies, assesses, and reports on areas of concern regarding the reliability of the North American BPS for the upcoming summer season. In addition, the SRA presents peak electricity demand and supply changes and highlights any unique regional challenges or expected conditions that might impact the BPS. The reliability assessment process is a coordinated reliability evaluation between the Reliability Assessment Subcommittee (RAS), the Regions, and NERC staff. This report reflects NERC’s independent assessment and is intended to inform industry leaders, planners, operators, and regulatory bodies so they are better prepared to take necessary actions to ensure BPS reliability. This report also provides an opportunity for the industry to discuss plans and preparations to ensure reliability for the upcoming summer period. In April 2020, NERC published its Special Report Pandemic Preparedness and Operational Assessment: Spring 2020 to advise electricity stakeholders about elevated risk to electric reliability as a result of the global health crisis. 1 NERC continues to assess risks to the reliability and security of the BPS from the global health crisis and reports on industry actions and preparedness in this SRA. 1 https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/NERC_Pandemic_Preparedness_and_Op_Assessment_Spring_2020.pdf
Summer Reliability Assessment 5
Findings
NERC’s annual SRA covers the Summer 2020 (June–September) period. This assessment provides an evaluation of resource and transmission system adequacy necessary to meet projected summer peak
demands. In addition to assessing resource adequacy, the SRA monitors and identifies potential reliability issues of interest and regional topics of concern. In 2020, there is heightened uncertainty in
demand projections stemming from the progression of the coronavirus (COVID-19) pandemic and the response of governments, society, and the electricity industry. The following key findings represent
NERC’s independent evaluation of electric generation and transmission capacity as well as potential operational concerns that may need to be addressed for the upcoming summer:
Sufficient capacity resources are expected to be in-service for the upcoming summer. In all areas, with the exception of ERCOT, the Anticipated Reserve Margin meets or surpasses the Reference
Margin Level, indicating that planned resources in these areas are adequate to manage risk of a capacity deficiency under normal conditions. 2 Assessment areas are prepared to meet potential
peak demand with or without pandemic-related demand reductions. Should pandemic related restrictions continue through the summer, peak demand is expected to be lower than forecast.
Texas RE-ERCOT. Projections for increased peak demand in ERCOT indicate the potential for energy emergency alerts (EEAs) during summer peak periods. Prior to the arrival of COVID-19 and
the resulting mitigations that have impacted electricity demand, ERCOT planners were expecting similarly tight operating conditions to those faced in Summer 2019. The ERCOT Anticipated
Reserve Margin has risen from 8.5% in Summer 2019 to 12.9% for the upcoming summer. The increase in reserve margin is driven by the addition of over 1.9 GW of on-peak resource capacity.
ERCOT’s forecast of peak demand for Summer 2020 is also forecasted to grow in 2020, but higher-growth projections have been tempered in recent months by COVID-19 economic impacts.
The potential for EEAs and operating mitigation at peak load remains.
Maintenance and preparations for summer operations impacted by pandemic. As summer peak operating season approaches each year, generator and transmission owners and operators engage
in extensive preparations, including preventive maintenance, supply stocking, and training programs. However, many normal efforts have been impinged by the global pandemic. To avoid the risk
of failing to complete maintenance on-time, some owners and operators have deferred or cancelled preseason maintenance in response to pandemic-related issues. Monitoring the progress of
ongoing efforts to prepare staff and equipment for summer will be important to ensuring the availability of anticipated resources to meet electricity demand. Furthermore, system operators must
be prepared to address demand forecast uncertainty and potentially challenging operating conditions as a result of low demand on the system.
Protecting critical electric industry workforce during the COVID-19 pandemic remains a priority for reliability and resilience. System and generation plant operators have implemented operating
postures and personnel restrictions prescribed by their pandemic plans in order to protect essential personnel and support reliable operations. Many of these measures will need to be maintained
for the foreseeable future. There is a continuing risk that control centers or plants could be temporarily shut down if a significant number of operators or plant employees test positive for COVID-
19 despite preparedness efforts. When relaxations can be implemented, operators will likely need to stay postured to return to heightened protections in response to dynamic public health
conditions.
Late-summer wildfire season in western United States and Canada poses risk to BPS reliability. Government agencies warn of the potential for above-normal wildfire risk beginning as early as
June in parts of the Western United States as well as Central and Western Canada. 3 Operation of the BPS can be impacted in areas where wildfires are active as well as areas where there is
heightened risk of wildfire ignition due to weather and ground conditions.
2 For more information, see the description of the “Reference Margin Level” in the Data Concepts and Assumptions section of this report or refer to NERC’s Long-term Reliability Assessment:
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2019.pdf
3 See North American Seasonal Fire Assessment and Outlook, April 2020: https://www.predictiveservices.nifc.gov/outlooks/NA_Outlook.pdfSummer Reliability Assessment 6
Resource Adequacy
The Anticipated Reserve Margin, which is based on available resource capacity, is a metric used to evaluate resource adequacy by comparing the projected capability of anticipated resources to serve
forecasted peak demand. 4 Large year-to-year changes in anticipated resources or forecasted peak demand (net internal demand) can greatly impact Planning Reserve Margin calculations. Other than in
ERCOT, all assessment areas have sufficient Anticipated Reserve Margins to meet or exceed their Reference Margin Level for Summer 2020 as shown in the Figure 1.
Although the pandemic introduces significant uncertainty into demand and some risk to generation resource availability, as discussed in the following section, the projections below provide indication that
adequate resources are available to meet peak demand.
79% | 79% 52% | 52%
Figure 1: Summer 2020 Anticipated/Prospective Reserve Margins Compared to Reference Margin Level
4 Generally, anticipated resources include generators and firm capacity transfers that are expected to be available to serve lo ad during electrical peak loads for the season. Prospective Resources are those that could be available but do not meet
criteria to be counted as Anticipated Resources. Refer to the Data Concepts and Assumptions section for additional information on Anticipated/Prospective Reserve Margins, Anticipated/Prospective Resources, and Reference Margin Levels.Summer Reliability Assessment 7
Changes from Year-to-Year
Understanding the changes from year-to-year is an essential step in assessing an area on a seasonal basis. Figure 2 provides the relative change from the Summer 2019 to the Summer 2020 period. The
Regional Assessment Dashboards provide details of the demand and resource components that make up the anticipated reserve margins for each assessment area. In the following areas, anticipated
reserve margin changed by more than five percentage points: none of the changes result in a resource adequacy concern for the upcoming summer.
NPCC Maritimes: The retirements of one coal-fired generator and two biomass generators contributed to lower anticipated reserve margins.
NPCC Ontario: Anticipated Reserve Margins decrease due to nuclear unit refurbishments and reductions in the contribution of demand response and hydro.
WECC BC and WECC SRSG: Reserve margin changes are attributed to revised variable generation capacity factors and changes in peak-hour demand.
WECC NWPP-US: Forecasted summer peak demand increased by 6,300 MW (13.5%) while resource levels were relatively stable, resulting in lower reserve margins.
97% | 79% 56% | 52%
Figure 2: Summer 2019 to Summer 2020 Anticipated Reserve Margins Year-to-Year ChangeSummer Reliability Assessment 8
Internal Demand
The changes in forecasted Net Internal Demand for each assessment area are shown in Figure 3. 5 Assessment areas develop these forecasts based on historic load and weather information as well as other
long-term projections.
Most assessment area demand projections in this assessment have not been decreased to account for COVID-19 mitigation measures. Although government and societal responses to halt the spread of
the coronavirus (i.e., shelter-in-place orders, minimal travel, and restrictions on public gatherings) have resulted in near-term decreased electricity demand, impact projections for summer are difficult to
forecast. ERCOT is an exception, where planners reduced the pre-seasonal peak demand forecast by 1,496 MW but still anticipate potentially record-setting peak demand. The demand projections used
in Figure 3 and elsewhere throughout this report are likely higher than would be expected with pandemic mitigation completely factored in.
Figure 3: Change in Net Internal Demand: 2020 Summer Forecast Compared to 2019 Summer Forecast
5 Changes in modeling and methods may also contribute to year-to-year changes in forecasted net internal demand projections.Summer Reliability Assessment 9
Pandemic Preparedness and Operational Assessment—Summer 2020
The global health crisis has elevated the electric reliability risk profile due to potential workforce disruptions, supply chain interruptions, and increased cyber security threats. In April, NERC released its
Pandemic Preparedness and Operational Assessment – Spring 2020 (special report) to advise electricity stakeholders of the reliability considerations and assess the operational preparedness of the BPS
owners and operators during pandemic conditions in April and May 2020. In its special report, NERC did not identify any specific threat or degradation to the reliable operation of the BPS for the spring
time frame. The ERO continues to assess risks and conditions and is pursuing all available avenues to continue coordination with federal, state, and provincial regulators as well as work with industry to
identify reliability implications and lessons learned.
Increased Reliability Risk Profile by Operating Period
Spring 2020 Summer 2020 Long-Term
• No specific reliability issue identified • Continued potential for workforce disruptions; • Potential changes to generation and
support service disruption transmission in-service dates
• Potential workforce disruptions
• Potential equipment and fuel supply chain • Increased remote operation of non-critical
• Supply chain interruption
disruptions staff
• Increased cyber security threat and monitoring
• Deferred generation maintenance and other • Changes to pandemic preparedness and
• Different system conditions including lower factors impacting unit availability operating plans based on lessons learned
demands and higher voltages. • Note: a more granular assessment will be
• Generation in-service dates
• System operators under sequester Included in NERC's 2020 Long-Term Reliability
Assessment
• Noncritical staff are remote
Since the start of the widening coronavirus infection in North America in February 2020, registered entities have taken steps from pandemic plans and industry advisories to maintain the reliability and
security of the BPS. In March 2020, the Electricity Subsector Coordinating Council (ESCC) issued the first version of the ESCC Resource Guide 6 as a resource for electric power industry leaders to guide
informed localized decisions in response to the COVID-19 global health emergency; it is updated on a regular basis as new approaches, planning considerations, and issues develop. The guide highlights
data points, stakeholders, and options to consider in making decisions about operational status while protecting the health and safety of employees, customers, and communities. Sharing experiences and
expertise helps users of the guide to make independent, localized decisions aimed at reducing negative impacts to the continent’s power supply during the COVID-19 global pandemic. In addition to
immediate measures designed to protect critical operations, personnel, and functions, entities are working to minimize risk to resource and BPS equipment availability, assure fuel supplies, and prepare
operating personnel for peak season.
Maintenance Preparations for Summer Impacted
Since electricity demand is lower in a typical spring season than peak summer and winter periods, Transmission and Generator Owners normally have the opportunity to schedule maintenance and address
training needs. Pandemic response and mitigation plans at national, state, provincial, and local levels can impact maintenance efforts by disrupting the flow of personnel and supply chains. Some delays
to transmission projects due to disrupted travel of specialized contractors has been reported. To avoid the risk of failing to complete maintenance on time, some owners and operators have deferred or
cancelled preseason maintenance in response to pandemic-related issues as can be seen by the MISO area example in Figure 4.
6 https://www.electricitysubsector.org/Summer Reliability Assessment 10
Maintenance Deferral
Figure 4: Generation Capacity Planned to be Off-line in MISO through May 31, 2020 (Scheduled February 20 and April 13, 2020).
In ERCOT, planners observed a higher-than-normal volume of generator maintenance outages in late March/early April possibly due to Generator Owners accelerating maintenance schedules to get ahead
of potential supply chain or personnel delays. Planners and operators continue to manage schedules of equipment outages into the summer season to ensure sufficient resource availability and transmission
system readiness. Maintenance that would have been performed prior to summer but is deferred can increase the risk of forced outages.
Operators in areas where a large portion of generators have deferred maintenance could experience higher-than-expected forced outages that could lead to generation supply deficiencies during periods
of peak demand. NERC is implementing codes for its Generator Availability Data System (GADS) that will support collection of data on outages with pandemic causes for use in analyzing reliability impacts
in later months. 7
Electricity supply risk can be compounded by risks to the generator and to their supply of fuel. Natural-gas-fired generators can be at risk to fuel supply infrastructure disruption from mechanical or other
issues; planners and operators in areas with impacted preseason maintenance are implementing measures to mitigate such risks. For example, in ISO-NE, the Electric/Gas Operations Committee has been
conducting weekly meetings to determine and assess pandemic impacts to pipelines. The ISO has also increased surveying of generator owners and operators to assess outage risks.
7 Information about GADS: https://www.nerc.com/pa/RAPA/gads/Pages/GeneratingAvailabilityDataSystem-(GADS).aspxSummer Reliability Assessment 11
Demand Impacts Vary and Cause Forecast Uncertainty
The pandemic is negatively impacting electricity demand in many parts of North America just as it has elsewhere around the world. Prior to summer, when government stay-at-home orders and societal
response were at their highest, some areas reported as much as 15% drop off in peak demand. However, these observed demand impacts varied across North America and in some areas were negligible.
Throughout the pandemic, many independent system operators and regional transmission operators have periodically reported on demand impacts. 8 In most areas, weather continues to be the
predominant factor in electricity demand. Diminished peak demand resulting from pandemic does not pose any meaningful risk to reliability for the summer season.
Many areas are experiencing variations in hourly load shapes as a result of changing societal behaviors and mechanisms implemented to halt the spread of the coronavirus. In general, these areas are
seeing below-normal ramp in demand in morning hours and lower evening demand as can be seen in Figure 5. Changes to pre-pandemic patterns can affect accuracy of day-ahead demand forecasts that
are relied upon to ensure resources are available for each hour of the day. In recent years, demand and resource forecasting has become more complex—and more critical—as the generation resource
mix has changed to include higher levels of variable generation, and load shape has changed with increasing solar photovoltaic (PV) resources. When operating entities began observing discrepancies
between predicted and actual demand as a result of pandemic behavior, many instituted measures designed to improve the accuracy of forecasts made available to system operators. In MISO and other
ISOs, support teams have increased the frequency of short-term demand forecast simulations.
Figure 5: Average Simulated and Actual Load in MISO Area for April 4–10, 2020
8For example, see reports from ERCOT and CAISO: http://www.caiso.com/Documents/COVID-19-Impacts-ISOLoadForecast-Presentation.pdf
http://www.ercot.com/content/wcm/lists/200201/ERCOT_COVID-19_Analysis_FINAL.pdfSummer Reliability Assessment 12
Potential Demand and Resource Challenges for System Operators Operating Reliability Considerations
Where pandemic restrictions persist through the summer, system operators could encounter difficult system characteristics, such as increased impact
of DERs on load profiles, distribution reverse power flows, higher than usual operating voltages, and minimum demands at all-time lows. Operating
challenges such as these need to be addressed in real-time and often by using complex tools for studying dynamic system conditions. Increased uncertainty in demand
projections and daily use
The effect of distributed energy resources (DERs) on system performance can become more pronounced as synchronous generation can be replaced
on the system during periods of lower minimum demand; operators could face challenges in maintaining sufficient amounts of frequency-responsive Potential for increased forced outages due
reserves necessary to regulate or arrest changes in frequency. Typically, DER effects on the system are more pronounced in the spring when milder to deferred maintenance, staff
temperatures reduce air conditioning load and increase efficiency in solar PV modules. With potentially lower demand on the system as a result of unavailability, or limited supplies and/or
the pandemic, these conditions could extend into early summer. In areas with higher DER penetration (e.g., California and North Carolina), minimum fuel
loads and reverse power flows from the distribution system can cause some challenges for system operators.
Higher than usual operating voltages
Operators in some areas may also have to contend with how a reduction in industrial and commercial loads could affect operating strategies and Light load conditions
emergency plans. The potential lack of industrial and commercial load could alter underfrequency or undervoltage load shedding plans that rely on Reverse power flow and increased
tripping these loads as well as demand response programs that may be relied on to support emergency operations. penetration levels of DERs
Utility Crews and Operators Must Stay Postured for Reliability, Security, and Resilience Potential for reduced effectiveness in
underfrequency/voltage load shedding
As the coronavirus crisis unfolds in the lead up to summer, the industry is preparing to operate with a significantly smaller workforce, an encumbered
supply chain, and limited support services for an extended and unknown period of time. Vigilance to cyber security threats intensifies as risks are schemes as industrial and commercial load
elevated due to a greater reliance on remote working arrangements. The business continuity and pandemic plans developed by the different operating may not be online
entities are designed to protect the people working for them and to ensure critical electricity operations and infrastructure are supported properly
throughout an emergency.
Protecting critical electric industry workforce during the COVID-19 pandemic remains a priority for reliability and resilience. System and Generator Operators have implemented operating postures and
personnel restrictions prescribed by their pandemic plans in order to protect essential personnel and support reliable operations. Many of these measures will need to be maintained for the foreseeable
future. There is a continuing risk that control centers or plants could be temporarily shut down if a significant number of operators or plant employees test positive for COVID-19 despite preparedness
efforts, including employee sequestration. As of April, many entities had begun developing return to work plans; however, the majority of entities indicated that they expected to maintain protective
protocols for operating personnel through summer and beyond. When relaxations can be implemented, operators will likely need to stay postured to return to heightened protections if warranted by
public health conditions.
An important component of BPS resilience and recovery from hurricanes and major storms is the effective mutual assistance rendered by organizations from outside the storm-affected areas. The
comprehensive plans in place to rapidly deploy support teams and equipment take on even greater complexity for the 2020 North American hurricane season (May–November) due to the need to safeguard
personnel from coronavirus infection. In April, the ESCC updated its Resource Guide to provide lessons learned from the experience of the utilities, electric cooperatives, and investor-owned electric
companies affected by a series of storms in late March and early April of this year. Lessons learned include considerations for maintaining social distancing at all times, planning for personnel protection
equipment needs, and increased need for local logistical and coordination personnel to support a decentralized response. 9
9 See ESCC Resource Guide, Version 7, April 27, 2020, p. 47–48.Summer Reliability Assessment 13 Cyber Security Risk and Information Sharing Electricity and other critical infrastructure sectors face elevated cyber security risks arising from the COVID-19 pandemic in addition to ongoing risks. Opportunistic actors are attempting to find and exploit new vulnerabilities that arise as entities shift work processes and locations to maintain business continuity. The Electricit y Infrastructure Sharing and Analysis Center (E-ISAC) continues to exchange information with its members and has posted communications and guidance from the ESCC and from government partners, and other advisories on its Portal; members are encouraged to check in regularly to receive updates. The E-ISAC also continues to provide information regarding emerging cyber threats; these include attacks on conferencing and remote access infrastructure, disinformation, and spear phishing campaigns attempting to harvest credentials and other information. Members are encouraged to actively share information regarding threats and other malicious activities with the E-ISAC to enable broader communication with other sector participants and government partners.
Summer Reliability Assessment 14
Operational Risks Highlighted for Summer 2020
Seasonal Operational Risk Assessments of Resource and Demand Scenarios
Areas can face energy shortfalls despite having Planning Reserve Margins that exceed Reference Margin Levels. Operating resources may be insufficient during periods of peak demand for reasons that
could include generator scheduled maintenance, forced outages due to normal and more extreme weather conditions and loads, and low-likelihood conditions that affect generation resource performance
or unit availability, including constrained fuel supplies. The Regional Assessment Dashboards section in this report includes a seasonal risk scenario for each area that illustrates potential variation in
resource and load as well as the potential effects that operating actions can have to mitigate shortfalls in operating reserves when insufficiencies occur. Figure 6 shows an example seasonal risk assessment
for the Southwest Power Pool (SPP) area that NERC developed using SRA data. A description of resource and demand variables is found in Table 1.
Figure 6: SPP Assessment Area Seasonal Risk AssessmentSummer Reliability Assessment 15
About the Seasonal Risk Assessment
The operational risk analysis shown in Figure 6 provides a deterministic scenario for understanding how various factors affecting resources and demand can combine to impact overall resource adequacy.
Adjustments are applied cumulatively to anticipated capacity, such as reductions for typical generation outages (maintenance and forced not already accounted for in anticipated resources) and additions
that represent the quantified capacity from operational tools, if any, that are available during scarcity conditions but have not been accounted for in the SRA reserve margins.
Resources throughout the scenario are compared against expected operating reserve requirements that are based on peak load and normal weather. The effects from low-probability, extreme events
are also factored in through additional resource derates or extreme resource scenarios and extreme summer peak load conditions. Because the seasonal risk scenario shows the cumulative impact
resulting from the occurrence of multiple low-probability events, the overall likelihood of the scenario is very low. An analysis similar to the SPP seasonal risk scenario in Figure 6 can be found for each
assessment area in the Regional Assessment Dashboards section of this report.
The seasonal risk assessment for the SPP assessment area shows that resources are available to meet peak summer demand, including normally hot and humid summer conditions. However, extreme heat
and summer conditions, such as those associated with record-setting temperatures, could increase demand and reduce generator performance enough to cause operating emergencies. A low-output wind
generation event, though rare, could lead to operating actions, including conservative operations plans and EEA declarations, to manage resources and demand. Despite anticipated resources in excess of
Reference Margin Levels as shown in Figure 1, operators in SPP and other areas of North America can face resource constraints during extreme summer weather.
During the past two summers, system operators in SPP needed to take operating actions, including issuing one EEA in August 2019, to address resource shortfalls. In some instances, operators were
responding to higher than expected planned and forced outages coupled with real time forecasting errors for load and wind. SPP has established operational mitigation teams and developed enhanced
processes and procedures to support operators in maintaining real time reliability.
Table 1: Resource and Demand Variables in the SPP Seasonal Risk Assessment
Resource Scenarios
Typical maintenance outages refer to an estimate of generation resources that will be out for maintenance during peak demand conditions. SPP calculated a value of
Typical Maintenance Outages
4,926 MW based on historical averages.
Typical forced outages refer to an estimate of generation resources that will experience forced outage during peak load conditions. SPP calculated a value of 4,638
Typical Forced Outages
MW based on historical averages.
Resource Derates for Extreme An estimated capacity derate due to extreme conditions is calculated and used for a low-likelihood resource scenario. The derate accounts for reduced capacity
Conditions (Low-likelihood) contributions due to generator performance in extreme conditions. SPP calculated a capacity derate of 2,276 MW for thermal generation due to extreme conditions.
Low-Wind Scenario (Low- The low-wind scenario is used to analyze the impact of low-likelihood weather conditions that severely reduce output from wind generation resources. A capacity
likelihood) adjustment of 5,017 MW is based on a low wind generator output historical event observed by system operators during summer peak conditions.
Operational Mitigations SPP estimates that certain operational mitigations can contribute 1,700 MW of additional resources to support maintaining operating reserve requirements.
Demand Scenarios
2020 Summer Net Internal Net internal demand is equal to total internal demand then reduced by the amount of controllable and dispatchable demand response projected to be available
Demand during the peak hour. It is based on historical average weather (i.e., forecasts for a 50/50 distribution).
A seasonal load adjustment (2,313 MW) is added to 2020 Net Internal Demand to account for extreme weather conditions. The adjustment is based on a 90/10
Extreme Summer Peak Load
statistical extreme load forecast.Summer Reliability Assessment 16 Seasonal Risk Assessments for Other Areas Seasonal risk scenarios for each assessment area are presented in the Regional Assessment Dashboards section of this report. Potential extreme generation resource outages and peak loads that can accompany extreme hot or humid weather may result in reliability risks in MISO, SPP, and ERCOT as well as the Canadian provinces of Manitoba, Saskatchewan, and the Maritimes. Parts of the system within the WECC area, including California ISO, could also experience resource shortfalls in low-likelihood resource derate scenarios. Under studied conditions for these areas, grid operators would need to employ operating mitigations or EEAs to obtain resources necessary to meet extreme peak demands. Wildfire Risk Potential and BPS Impacts Government agencies predict normal to below-normal wildfire risk at the start of summer for the West Coast of the United States and the southwestern states. However, the latest three-month Seasonal Fire Assessment and Outlook published by the National Interagency Fire Center, Natural Resources Canada, and National Meteorological Service in Mexico warns that the trend toward warmer, drier weather could lead to above normal wildland fire potential in Northern California, Oregon, and Washington beginning in June. 10 Across most of western Canada, weather patterns and forecasts also suggest increased potential for wildland fires. Operation of the BPS can be impacted in areas where wildfires are active as well as areas where there is heightened risk of wildfire ignition due to weather and ground conditions. Wildfire prevention planning in California and other areas include power shut-off programs in high fire-risk areas. When conditions warrant implementing these plans, power lines, including transmission-level lines, may be preemptively de-energized in high fire-risk areas to prevent wildfire ignitions. Other wildfire risk mitigation activities include implementing enhanced vegetation management, equipment inspections, system hardening, and added situational awareness measures. 10 See North American Seasonal Fire Assessment and Outlook, May 2020: https://www.predictiveservices.nifc.gov/outlooks/NA_Outlook.pdf
Summer Reliability Assessment 17 Regional Assessment Dashboards The following assessment area dashboards and summaries were developed based on data and narrative information collected by NERC from the Regional Entities on an assessment area basis.
Summer Reliability Assessment 18
Seasonal Risk Scenario MISO Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand (50/50) 124,744 124,866 0.1%
Demand Response: Available 6,385 6,172 -3.3%
Net Internal Demand 118,359 118,694 0.3%
Resource Projections MW MW Net Change
Existing-Certain Capacity 139,220 140,636 1.0%
MISO Tier 1 Planned Capacity 0 0 -
The Midcontinent Independent System Operator, Net Firm Capacity Transfers 1,955 2,795 42.9%
Inc. (MISO) is a not-for-profit, member-based Anticipated Resources 141,175 143,430 1.6%
organization administering wholesale electricity Existing-Other Capacity 591 290 -50.9%
markets that provide customers with valued Prospective Resources 141,766 143,720 1.4%
service; reliable, cost-effective systems and Reserve Margins Percent Percent Annual Difference
operations; dependable and transparent prices;
Anticipated Reserve Margin 19.3% 20.8% 1.5
open access to markets; and planning for long-
term efficiency. Prospective Reserve Margin 19.8% 21.1% 1.3
Reference Margin Level 16.8% 18.0% 1.2
MISO manages energy, reliability, and operating
reserve markets that consist of 36 local Balancing
The table and chart above provide potential summer peak demand and resource Highlights
Authorities and 394 market participants that condition information. The table on the right presents a standard seasonal Summer scenarios with high resource outages and high demand may
serves approximately 42 million customers. assessment and comparison to the previous year’s assessment. The chart above require use of load modifying resources during peak periods as load
Although parts of MISO fall in three NERC presents deterministic scenarios for further analysis of different demand and modifying resources become an increasingly important segment of MISO’s
Regions, MRO is responsible for coordinating data resource levels, with adjustments for normal and extreme conditions. MISO resource portfolio.
and information submitted for NERC’s reliability determined the adjustments to summer capacity and peak demand based on
assessments. methods or assumptions that are summarized below. See the Data Concepts and Though MISO remains resource adequate for the 2020 summer, some
Assumptions for more information about this table and chart. areas may be resource and import constrained presenting local operating
challenges.
Risk Scenario Summary
Observation: Near-term impacts of COVID-19 have resulted in generally lower loads and
Resources meet operating reserve requirements under normal demand and outage shifted morning and evening peaks to later hours. It is unclear how
scenarios. Extreme summer peak demand or outages could result in a need to employ observed trends will change through the summer months.
operating procedures to mitigate resource shortfall.
Scenario Assumptions
Coal Extreme Peak Load: 90/10 forecast
Petroleum Outages: Average from highest peak hour over the past five summers
Natural Gas
Wind
Conventional Hydro
Pumped Storage
NuclearSummer Reliability Assessment 19
Seasonal Risk Scenario MRO-Manitoba Hydro Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand (50/50) 3,224 3,272 1.5%
Demand Response: Available 0 0 -
Net Internal Demand 3,224 3,272 1.5%
Resource Projections MW MW Net Change
MRO-Manitoba Hydro
Existing-Certain Capacity 5,161 5,239 1.5%
Tier 1 Planned Capacity 0 0 -
Manitoba Hydro is a provincial crown corporation
that provides electricity to about 580,000 Net Firm Capacity Transfers -1,408 -1,526 8.4%
customers throughout Manitoba and natural gas Anticipated Resources 3,753 3,713 -1.1%
service to about 282,000 customers in various Existing-Other Capacity 215 125 -41.6%
communities throughout Southern Manitoba.
Prospective Resources 3,968 3,838 -3.3%
The Province of Manitoba has a population of
about 1.3 million people in an area of 250,946 Reserve Margins Percent Percent Annual Difference
square miles. Anticipated Reserve Margin 16.4% 13.5% -2.9
Prospective Reserve Margin 23.1% 17.3% -5.8
Manitoba Hydro is winter peaking. No change in
the footprint area is expected during the Reference Margin Level 12.0% 12.0% 0.0
assessment period. Manitoba Hydro is its own
The table and chart above provide potential summer peak demand and resource Highlights
Planning Coordinator and Balancing Authority.
Manitoba Hydro is a coordinating member of
condition information. The table on the right presents a standard seasonal Manitoba Hydro has implemented measures to minimize coronavirus
MISO. MISO is the Reliability Coordinator for assessment and comparison to the previous year’s assessment. The chart above impact risk to operations. While the COVID-19 Pandemic is expected to be
Manitoba Hydro. presents deterministic scenarios for further analysis of different demand and present over the summer assessment period, an impact on BPS reliability
resource levels with adjustments for normal and extreme conditions. MRO-Manitoba is not anticipated.
determined the adjustments to capacity and peak demand based on methods or
assumptions that are summarized below. See the Data Concepts and Assumptions Reservoir storage levels are above average and more than adequate to
for more information about this table and chart. withstand the design-basis drought conditions.
Risk Scenario Summary
Resources meet operating reserve requirements under normal demand and outage
scenarios.
Scenario Assumptions
Extreme Peak Demand: All-time highest peak load
Outages: Based on historical operating experience
Extreme Derates: Thermal units derated for extreme temperature where
Natural Gas appropriate.
Conventional HydroSummer Reliability Assessment 20
Seasonal Risk Scenario MRO-SaskPower Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand (50/50) 3,553 3,480 -2.1%
Demand Response: Available 85 60 -29.4%
Net Internal Demand 3,468 3,420 -1.4%
Resource Projections MW MW Net Change
Existing-Certain Capacity 3,907 3,904 -0.1%
MRO-SaskPower Tier 1 Planned Capacity 0 0 -
Saskatchewan is a province of Canada and Net Firm Capacity Transfers 25 125 400.0%
comprises a geographic area of 651,900 Anticipated Resources 3,932 4,029 2.5%
square kilometers (251,700 square miles) Existing-Other Capacity 0 0 -
with approximately 1.1 million people. Peak Prospective Resources 3,932 4,029 2.5%
demand is experienced in the winter. The Reserve Margins Percent Percent Annual Difference
Saskatchewan Power Corporation Anticipated Reserve Margin 13.4% 17.8% 4.4
(SaskPower) is the Planning Coordinator and Prospective Reserve Margin 13.4% 17.8% 4.4
Reliability Coordinator for the province of
Reference Margin Level 11.0% 11.0% 0.0
Saskatchewan and is the principal supplier of
electricity in the province. SaskPower is a The table and chart above provide potential summer peak demand and resource Highlights
provincial crown corporation, under condition information. The table on the right presents a standard seasonal Saskatchewan experiences high load in summer as a result of extreme hot
provincial legislation, and is responsible for assessment and comparison to the previous year’s assessment. The chart above weather.
the reliability oversight of the Saskatchewan presents deterministic scenarios for further analysis of different demand and
Bulk Electric System (BES) and its resource levels with adjustments for normal and extreme conditions. MRO- SaskPower conducts an annual summer joint operating study with
interconnections. SaskPower determined the adjustments to capacity and peak demand based on Manitoba Hydro with inputs from Basin Electric (North Dakota) and
methods or assumptions that are summarized below. See the Data Concepts and prepares operating guidelines for any identified issues.
Assumptions for more information about this table and chart. The risk of operating reserve shortage during peak load times or EEAs could
Risk Scenario Summary increase if large generation forced outage occurs during peak load times in
Resources meet operating reserve requirements under normal scenarios. Extreme the end of August to early October 2020 when 641 MW of SaskPower’s
summer peak load and outage conditions could result in the need to employ operating natural gas generating station is off-line for overhaul maintenance.
mitigations (i.e., demand response, transfers, and short-term load interruption.)
Scenario Assumptions
Extreme Peak Load: Peak demand with lighting and all large consumer loads
Maintenance Outages: Estimated based on average maintenance outages for
June, July, August, and September for 2019
Coal Forced Outages: Estimated using SaskPower forced outage model
Natural Gas Extreme Derates: Derate on natural gas units based on historic data and
manufacturer data
Conventional HydroSummer Reliability Assessment 21
Seasonal Risk Scenario NPCC-Maritimes Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand (50/50) 3,255 3,370 3.5%
Demand Response: Available 289 369 27.7%
Net Internal Demand 2,966 3,001 1.2%
Resource Projections MW MW Net Change
Existing-Certain Capacity 5,842 5,312 -9.1%
NPCC-Maritimes Tier 1 Planned Capacity 0 0 0.0%
The Maritimes assessment area is a winter- Net Firm Capacity Transfers 0 53 0.0%
peaking NPCC subregion that contains two Anticipated Resources 5,842 5,365 -8.2%
Balancing Authorities. It is comprised of the Existing-Other Capacity 0 0 0.0%
Canadian provinces of New Brunswick, Nova Prospective Resources 5,842 5,365 -8.2%
Scotia, and Prince Edward Island, and the
Reserve Margins Percent Percent Annual Difference
northern portion of Maine that is radially
connected to the New Brunswick power system. Anticipated Reserve Margin 97.0% 78.8% -18.2
The area covers 58,000 square miles with a total Prospective Reserve Margin 97.0% 78.8% -18.2
population of 1.9 million. Reference Margin Level 20.0% 20.0% 0.0
The table and chart above provide potential summer peak demand and resource Highlights
condition information. The table on the right presents a standard seasonal The Maritimes area has not identified any operational issues that are
assessment and comparison to the previous year’s assessment. The chart above expected to impact system reliability. If an event was to occur, there are
presents deterministic scenarios for further analysis of different demand and emergency operations procedures in place. All of the area’s declared firm
resource levels with adjustments for normal and extreme conditions. NPCC-Maritimes capacity is expected to be operational for the summer operating period.
determined the adjustments to capacity and peak demand based on methods or
assumptions that are summarized below. See the Data Concepts and Assumptions As part of the planning process, dual-fueled units will have sufficient
for more information about this table and chart. supplies of heavy fuel oil (HFO) on-site to enable sustained operation in the
event of natural gas supply interruptions.
Risk Scenario Summary
Resources meet operating requirements under normal peak load scenario. Extreme The effects of the COVID-19 pandemic on load patterns, energy use, and
summer peak load and outage conditions could result in the need to employ operating peak demands will continue to be evaluated as the pandemic evolves.
mitigation to manage resource shortfall. The Maritimes are evaluating contingency plans for transmission,
distribution and generation planned work, planned maintenance and
Scenario Assumptions
forced outages to proceed conservatively while mitigating short term and
Extreme Peak Load: 90/10 forecast longer term reliability risks.
Coal
Petroleum Outages: Based on historical operating experience
Natural Gas Extreme Derates: An extreme, low-likelihood scenario is used whereby thermal
Biomass units are derated for extreme temperature and all wind unit capacity is
unavailable
Wind
Conventional Hydro
Run of River Hydro
Nuclear
OtherSummer Reliability Assessment 22
Seasonal Risk Scenario NPCC-New England Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand (50/50) 25,323 25,158 -0.7%
Demand Response: Available 340 443 30.3%
Net Internal Demand 24,983 24,715 -1.1%
Resource Projections MW MW Net Change
Existing-Certain Capacity 30,144 30,791 2.1%
NPCC-New England Tier 1 Planned Capacity 1,185 0 -100.0%
ISO New England (ISO-NE) Inc. is a regional Net Firm Capacity Transfers 1,328 1,510 13.7%
transmission organization that serves Anticipated Resources 32,657 32,301 -1.1%
Connecticut, Maine, Massachusetts, New Existing-Other Capacity 704 324 -54.0%
Hampshire, Rhode Island, and Vermont. It is Prospective Resources 33,361 32,625 -2.2%
responsible for the reliable day-to-day operation
Reserve Margins Percent Percent Annual Difference
of New England’s bulk power generation and
transmission system, and it also administers the Anticipated Reserve Margin 30.7% 30.7% 0.0
area’s wholesale electricity markets and manages Prospective Reserve Margin 33.5% 32.0% -1.5
the comprehensive planning of the regional BPS. Reference Margin Level 18.3% 18.3% 0.0
The New England regional electric power system
serves approximately 14.5 million people over The table and chart above provide potential summer peak demand and resource Highlights
68,000 square miles. condition information. The table on the right presents a standard seasonal The New England Area expects to have sufficient resources to meet the
assessment and comparison to the previous year’s assessment. The chart above 2020 summer peak demand forecast of 25,158 MW for the week beginning
presents deterministic scenarios for further analysis of different demand and July 5, 2020, with a projected net margin of 3,197MW (12.7%). The 2020
resource levels with adjustments for normal and extreme conditions. NPCC-New summer demand forecast is 165 MW (0.7%) less than the 2019 summer
England determined the adjustments to capacity and peak demand based on methods forecast of 25,323 MW and takes into account the demand reductions
or assumptions that are summarized below. See the Data Concepts and Assumptions associated with energy efficiency, load management, behind-the-meter
for more information about this table and chart. photovoltaic (BTM-PV) systems, and distributed generation.
Risk Scenario Summary With residents and businesses across New England changing their behavior
Resources meet operating reserve requirements under studied scenarios. in response to the COVID-19 pandemic, ISO New England is seeinga decline
Scenario Assumptions in system demand of approximately 3–5% compared to what would
normally be expected under weather conditions in the area. These
Extreme Peak Load: 90/10 Forecast percentages may change over time.
Outages: Based on weekly averages In addition to overall declines in consumer demand, these societal changes
Operating Mitigations: Based on ISO-NE operating procedures are also affecting demand patterns across the region. Though the
pandemic is affecting energy use, weather conditions remain the primary
Coal
drivers of system demand. ISO-NE will continuously monitor these ever-
Petroleum
changing trends in load patterns and make the appropriate adjustments to
Natural Gas calculate an accurate load forecast. The area’s power system continues to
Biomass remain reliable.
Conventional Hydro
Pumped Storage
NuclearSummer Reliability Assessment 23
Seasonal Risk Scenario NPCC-New York Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand
32,382 32,296 -0.3%
(50/50)
Demand Response: Available 1,309 1,282 -2.1%
Net Internal Demand 31,073 31,014 -0.2%
Resource Projections MW MW Net Change
NPCC-New York Existing-Certain Capacity 37,304 38,475 3.1%
The New York Independent System Operator Tier 1 Planned Capacity 27 101 274.8%
(NYISO) is the only Balancing Authority within the
Net Firm Capacity Transfers 1,452 1,562 7.6%
state of New York. NYISO is a single-state ISO that
was formed as the successor to the New York Anticipated Resources 38,783 40,138 3.5%
Power Pool—a consortium of the eight IOUs —in Existing-Other Capacity 0 0 0.0%
1999. NYISO manages the New York State Prospective Resources 38,783 40,138 3.5%
transmission grid that encompasses approximately
11,000 miles of transmission lines, more than Reserve Margins Percent Percent Annual Difference
47,000 square miles, and serving the electric needs Anticipated Reserve Margin 24.8% 29.4% 4.6
of 19.5 million people. New York experienced its Prospective Reserve Margin 24.8% 29.4% 4.6
all-time peak load of 33,956 MW in the summer of
Reference Margin Level 15.0% 15.0% 0.0
2013.
The NERC Reference Margin Level is 15%. Wind, The table and chart above provide potential seasonal peak demand and resource Highlights
grid-connected solar, and run-of-river totals were condition information. The table on the right presents a standard seasonal assessment NYISO is not anticipating any operational issues in the New York control
derated for this calculation. However, New York and comparison to the previous year’s assessment. The chart above presents area for the upcoming summer. Adequate capacity margins are anticipated
requires load serving entities to procure capacity deterministic scenarios for further analysis of different demand and resource levels and existing operating procedures are sufficient to handle any issues that
for their loads equal to their peak demand plus an with adjustments for normal and extreme conditions. NPCC-New York determined the
IRM. The IRM requirement represents a
may occur.
adjustments to capacity and peak demand based on methods or assumptions that are
percentage of capacity above peak load forecast summarized below. See the Data Concepts and Assumptions for more information New York requires load serving entities to procure capacity for their loads
and is approved annually by the New York State equal to their peak demand plus an Installed Reserve Margin (IRM). The
Reliability Council (NYSRC). NYSRC approved the
about this table and chart.
IRM requirement represents a percentage of capacity above peak load
2020–2021 IRM at 18.9%. Risk Scenario Summary forecast and is determined and approved annually by the New York State
Resources meet operating reserve requirements under studied scenarios. Reliability Council (NYSRC). NYSRC approved a 2020–2021 IRM of 18.9%.
Scenario Assumptions The IRM meets the NPCC and NYSRC criterion of a loss of load expectation
of no greater than 0.1 days per year. Its calculation is based on a study that
Extreme Peak Demand: 90/10 load forecast with demand response adjustments accounts for the forced outage rates of thermal generators, the peak load
Extreme Derates: Near-zero MW due to summer peaking area forecast, the load forecast uncertainty, the actual hourly production data
Coal for wind and solar over the most recent five-year calendar period, long
Typical Outages: Based on scheduled maintenance and GADS forced outage data
Petroleum term capacity imports and exports, demand response programs derated to
Operational Mitigation: 3.1 GW based on operational/emergency procedures in account for historic availability, various emergency operation procedures,
Natural Gas
NYISO Emergency Operations Manual and assistance from neighboring control areas. Historically since 2000, the
Conventional Hydro
IRM has ranged between 15.0% and 18.9%.
Run of River Hydro
Pumped Storage
NuclearSummer Reliability Assessment 24
Seasonal Risk Scenario NPCC-Ontario Resource Adequacy Data
Demand, Resource, and
2019 SRA 2020 SRA 2019 vs. 2020 SRA
Reserve Margin
Demand Projections MW MW Net Change
Total Internal Demand (50/50) 22,105 22,195 0.4%
Demand Response: Available 790 518 -34.5%
Net Internal Demand 21,315 21,677 1.7%
Resource Projections MW MW Net Change
Existing-Certain Capacity 26,581 25,719 -3.2%
NPCC-Ontario Tier 1 Planned Capacity 924 49 -94.7%
The Independent Electricity System Operator
Net Firm Capacity Transfers -102 0 -100.0%
(IESO) is the Balancing Authority and Reliability
Coordinator for the province of Ontario. In Anticipated Resources 27,403 25,768 -6.0%
addition to administering the area’s wholesale Existing-Other Capacity 0 0 0.0%
electricity markets, the IESO plans for Ontario’s
Prospective Resources 27,403 25,768 -6.0%
future energy needs. Ontario covers more than
415,000 square miles and has a population of Reserve Margins Percent Percent Annual Difference
more than 14 million. Ontario is interconnected Anticipated Reserve Margin 28.6% 18.9% -9.7
electrically with Québec, MRO-Manitoba, states in Prospective Reserve Margin 28.6% 18.9% -9.7
MISO (Minnesota and Michigan), and NPCC-New
York. Reference Margin Level 14.9% 14.6% -0.3
Ontario IESO treats demand response as a The table and chart above provide potential summer peak demand and resource Highlights
resource for its own assessments while in the condition information. The table on the right presents a standard seasonal The IESO expects to have sufficient generation supply for Summer 2020.
NERC assessment demand response is used as a assessment and comparison to the previous year’s assessment. The chart above
load-modifier. As a result, the total internal
Likewise, Ontario’s transmission system is expected to continue to reliably
presents deterministic scenarios for further analysis of different demand and supply province-wide demand throughout the summer season.
demand, reserve margin, and Reference Margin
resource levels with adjustments for normal and extreme conditions. NPCC-Ontario
Level values differ in IESO’s reports when
determined the adjustments to capacity and peak demand based on methods or Napanee Generating Station, a 994 MW natural-gas-fired plant, was added
compared to NERC reports. to Ontario’s generation fleet in March 2020. The Darlington Nuclear Unit
assumptions that are summarized below. See the Data Concepts and Assumptions
for more information about this table and chart. G2 (936 MW) is expected to return to service following refurbishment prior
to summer.
Risk Scenario Summary
Resources meet operating reserve requirements under studied scenarios. The year-on-year reduction in anticipated/prospective reserve margin is
due to a greater number of nuclear units on refurbishment outage as well
Scenario Assumptions as reductions in demand response and hydroelectric contributions.
Extreme Peak Load: Determined from the most severe historical weather The ongoing transmission outage of the phase angle regulator on the L33
Extreme Derates: Based on thermal unit derating curves and historical hydro circuit at the New York-St Lawrence interconnection continues to impact
performance for a low-water year import and export capacity between Ontario and New York. The issue is
being jointly managed by all involved parties.
Petroleum Operational Mitigation: 2,000 MW imports assessed as available from
Natural Gas neighbors
Biomass
Wind
Conventional Hydro
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